Multiple distributed sensors along a drillstring

ABSTRACT

Systems and methods for downhole measurement and communications are disclosed. The system includes a communications medium, at least partially disposed in a drillpipe, a processor coupled to the communications medium, at least two sensor modules coupled to the communications medium, where at least one of the sensor modules is along a drillpipe, and at least one communications coupler to couple at least one sensor module to the communications medium.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to commonly owned U.S. provisionalpatent application Ser. No. 60/550,033, filed Mar. 4, 2004, entitled“Multiple Distributed Sensors Along A Drillpipe,” by Daniel Gleitman.

BACKGROUND

As oil well drilling becomes increasingly complex, the importance ofcollecting downhole data while drilling increases.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a system for surface real-time processing of downhole data.

FIG. 2 illustrates a portion of drillpipe with an affixed sensor and acommunications medium.

FIG. 3 illustrates a portion of drillpipe with a sensor module and asensor-module receptacle

FIG. 4 is a cut-away diagram of the pin-end of a drillpipe joint withsensors affixed to the joint.

FIG. 5 is a cut-away diagram of a sub with a sensor module.

FIG. 6 is a cut-away diagram of a drillpipe joint with a sensor modulein the box portion.

FIG. 7 is a cut-away diagram of a sub with a sensor module in the boxportion.

FIG. 8 illustrates drillpipe joints and a gasket.

FIG. 9 shows a block diagram for a sensor module.

FIG. 10 shows a block diagram of a drillpipe coupler.

FIGS. 11 and 12 illustrate connectors for sensor couplers and drillpipecouplers.

FIGS. 13-17 are block diagrams of a borehole analysis method.

DETAILED DESCRIPTION

As shown in FIG. 1, oil well drilling equipment 100 (simplified for easeof understanding) may include a derrick 105, derrick floor 110, drawworks 115 (schematically represented by the drilling line and thetraveling block), hook 120, swivel 125, kelly joint 130, rotary table135, drillpipe 140, one or more drill collars 145, one or more MWD/LWDtools 150, one or more subs 155, and drill bit 160. Drilling fluid isinjected by a mud pump 190 into the swivel 125 by a drilling fluidsupply line 195, which may include a standpipe 196 and kelly hose 197.The drilling fluid travels through the kelly joint 130, drillpipe 140,drill collars 145, and subs 155, and exits through jets or nozzles inthe drill bit 160. The drilling fluid then flows up the annulus betweenthe drillpipe 140 and the wall of the borehole 165. One or more portionsof borehole 165 may comprise open hole and one or more portions ofborehole 165 may be cased. The drillpipe 140 may be comprised ofmultiple drillpipe joints. The drillpipe 140 may be of a single nominaldiameter and weight (i.e. pounds per foot) or may comprise intervals ofjoints of two or more different nominal diameters and weights. Forexample, an interval of heavy-weight drillpipe joints may be used abovean interval of lesser weight drillpipe joints for horizontal drilling orother applications. The drillpipe 140 may optionally include one or moresubs 155 distributed among the drillpipe joints. If one or more subs 155are included, one or more of the subs 155 may include sensing equipment(e.g., sensors), communications equipment, data-processing equipment, orother equipment. The drillpipe joints may be of any suitable dimensions(e.g., 30 foot length). A drilling fluid return line 170 returnsdrilling fluid from the borehole 165 and circulates it to a drillingfluid pit (not shown) and then the drilling fluid is ultimatelyrecirculated via the mud pump 190 back to the drilling fluid supply line195. The combination of the drill collar 145, MWD/LWD tools 150, anddrill bit 160 is known as a bottomhole assembly (or “BHA”). Thecombination of the BHA, the drillpipe 140, and any included subs 155, isknown as the drillstring. In rotary drilling the rotary table 135 mayrotate the drillstring, or alternatively the drillstring may be rotatedvia a top drive assembly.

The terms “couple” or “couples,” as used herein are intended to meaneither an indirect or direct connection. Thus, if a first device couplesto a second device, that connection may be through a direct connection,or through an indirect electrical connection via other devices andconnections. The term “upstream” as used herein means along a flow pathtowards the source of the flow, and the term “downstream” as used hereinmeans along a flow path away from the source of the flow. The term“uphole” as used herein means along the drillstring or the hole from thedistal end towards the surface, and “downhole” as used herein meansalong the drillstring or the hole from the surface towards the distalend.

It will be understood that the term “oil well drilling equipment” or“oil well drilling system” is not intended to limit the use of theequipment and processes described with those terms to drilling an oilwell. The terms also encompass drilling natural gas wells or hydrocarbonwells in general. Further, such wells can be used for production,monitoring, or injection in relation to the recovery of hydrocarbons orother materials from the subsurface.

One or more downhole sensor modules 175 are distributed along thedrillstring, with the distribution depending on the type of sensor andthe needs of the system. One or more of the downhole sensor modules maybe located on or within one or more portions of drillpipe. Otherdownhole sensor modules 175 may be located on or within subs 155, whichmay be located between sections of drillpipe. Other downhole sensormodules 175 may located on or within the drill collar 145 or the MWD/LWDtools 150. Still other downhole sensor modules 180 may be located on orwithin the bit 180. The downhole sensors incorporated in the downholesensor modules, as discussed below, may include pressure sensors, strainsensors, acceleration sensors, temperature sensors, acoustic sensors,gravitational field sensors, gyroscopes, resistivity sensors, weightsensors, torque sensors, bending-moment sensors, vibration sensors,rotation sensors, rate of penetrations sensors, magnetic field sensors,calipers, electrodes, gamma ray detectors, density sensors, neutronsensors, dipmeters, imaging sensors, and other sensors useful in welllogging and well drilling.

Other sensor modules 175 may be located at or near the surface tomeasure, for example, one or more of drilling fluid supply line (e.g.standpipe) or return line pressures. In many cases a sensor module 175located on or along the standpipe 196 (or other drilling fluid supplyline location) may be used to provide drillstring interior pressuremeasurements at or near the top of the drillstring or borehole 165. Incertain example implementations, the drillstring interior pressure maybe determined inferentially based on pressure measurements, using, forexample, pressure measurements taken from the drilling fluid supplyline. In some example implementations, a sensor module 175 located on oralong a return line may be used to provide drillstring exterior orannulus pressure measurements at or near the top of the drillstring orborehole 165. In some example systems, drillstring exterior or annuluspressure measurements at or near the top of the drillstring or borehole165 may be determined inferentially, using, for example, pressuremeasurements taken on a return line. In some example systems,drillstring exterior pressure at the top of the drillstring or borehole165 may be determined inferentially based on atmospheric pressure. Stillother sensor modules 175 may be affixed to one or more locations alongthe borehole 165. Other sensor modules 175 may be circulated in thedrilling fluid.

In general the sensor modules 175 may include one or more sensor devicesto measure one or more physical properties. The sensor devices maycomprise strain gauge devices, semiconductor devices, photonic devices,quartz crystal devices, fiber optic devices, or other devices to converta physical property into an electrical or photonic signal. In certainembodiments, the physical property values may be directly obtained fromthe output of the one or more sensor devices in the sensor modules 175.In other embodiments, property value measurements may be obtained basedon the output of the one or more sensor devices in conjunction withother data. For example, the measured property value may be determinedbased on material properties or dimensions, additional sensormeasurements, analysis, or calibration.

One or more sensor modules 175 or one or more sensor devices within asensor module 175 may measure one or more components of a physicalproperty. In the case of sensor modules 175 to measure to measure one ormore pressures, the components of the physical property (i.e., pressure)may include one or more static or stagnation pressures. For example, oneor more sensor modules 175 or one or more sensor devices in the sensormodules 175 may be oriented perpendicular to streamlines of the drillingfluid flow. One or more sensor modules 175 or one or more sensor devicesin one or more sensor modules 175 may measure stagnation pressure byorienting the sensor modules 175 or the sensor devices to face, orpartially face, into the drilling fluid flow. In certainimplementations, one or more sensor modules 175 or one or more sensordevices in a sensor module 175 may use an extended pitot tube approachor a shallow ramping port to orient the sensor modules 175 or sensordevice in sensor module 175 to face, or partially face, into thedrilling fluid flow. The measurement accuracy of the stagnation pressuremay vary depending on a degree of boundary layer influence.

In the case of sensor modules 175 or one or more sensor devices within asensor module 175 to measure one or more forces, the components of thephysical property (i.e. force) may include axial tension or compression,or torque, along the drillpipe. One or more sensor modules 175 or one ormore sensor devices within a sensor module 175 may be used to measureone or more force components with which force components reacted by orconsumed by the borehole 165, such as borehole-drag or borehole-torque,along the drillpipe may be determined. One or more sensor modules 175 orone or more sensor devices within a sensor module 175 may be used tomeasure one or more other force components such as pressure-inducedforces, bending forces, or other forces. One or more sensor modules 175or one or more sensor devices within a sensor module 175 may be used tomeasure combinations of forces or force components. In certainimplementations, the drillstring may incorporate one or more sensors tomeasure parameters other than force, such as temperature, pressure, oracceleration.

In the case of sensor modules 175 or sensor devices within a sensormodule 175 to measure acceleration, one or more of the sensor modules175 or sensor devices may measure the acceleration of the drillpipe 140in one or more directions. For example, one or more sensor modules 175or one or more sensor devices within a sensor module 175 may measure theacceleration of the drillpipe due to the rotation of the drillpipe 140.Other sensor modules 175 or one or more sensor devices within a sensormodule 175 may measure the acceleration of the drillpipe in one or moredirections along the borehole 165.

In one example implementation, one or more sensor modules 175 arelocated on or within the drillpipe 140. Other sensor modules 175 may beon or within one or more drill collars 145 or the one or more MWD/LWDtools 150. Still other sensor modules 175 may be in built into, orotherwise coupled to, the bit 160. Still other sensor modules 175 may bedisposed on or within one or more subs 155. One or more sensor modules175 may provide one or more force or torque components experienced bythe drillstring at surface. In one example implementation, one or moresensor modules 175 may be incorporated into the draw works 115, hook120, swivel 125, or otherwise employed at surface to measure the one ormore force or torque components experienced by the drillstring at thesurface.

The one or more sensor modules 175 may be coupled to portions of thedrillstring by adhesion or bonding. This adhesion or bonding may beaccomplished using bonding agents such as epoxy or fasters. The one ormore sensor modules 175 may experience a force, strain, or stress fieldrelated to the force, strain, or stress field experienced proximately bythe drillstring component that is coupled with the sensor module 175.Other sensor modules 175 may be coupled to portions of the drillstringby threading or with use of fasters.

Other sensor modules 175 or one or more sensor devices within a sensormodule 175 may be coupled to not experience all, or a portion of, thephysical property (e.g., acceleration, pressure, force, strain, orstress field) experienced by the drillstring component coupled proximateto the sensor module 175. Sensor modules 175 or sensor devices within asensor module 175 coupled in this manner may, instead, may experienceother ambient conditions, such as temperature. These sensor modules 175or sensor devices within a sensor module 175 may be used for signalconditioning, compensation, or calibration.

The sensor modules 175 may be coupled to one or more of: interiorsurfaces of drillstring components (e.g. bores), exterior surfaces ofdrillstring components (e.g. outer diameter), recesses between an innerand outer surface of drillstring components. The sensor modules 175 maybe coupled to one or more faces or other structures that are orthogonalto the axes of the diameters of drillstring components. The sensormodules 175 may be coupled to drillstring components in one or moredirections or orientations relative to the directions or orientations ofparticular force components or combinations of physical propertycomponents to be measured.

In certain implementations, sensor modules 175 or one or more sensordevices within a sensor module 175 may be coupled in sets to drillstringcomponents. In other implementations, sensor modules 175 may comprisesets of sensor devices. When sets of sensor modules 175 or sets ofsensor devices are employed, the elements of the sets may be coupled inthe same, or different ways. For example, the elements in a set ofsensor modules 175 or sensor devices may have different directions ororientations, relative to each other. For example, in the case of sensormodules 175 to measure one or more forces, using set of sensor modules175 or a set of sensor devices, one or more elements of the set may bebonded to experience a strain field of interest and one or more otherelements of the set (i.e. “dummies”) may be bonded to not experience thesame strain field. The dummies may, however, still experience one ormore ambient conditions. Elements in a set of sensor modules 175 orsensor devices may be symmetrically coupled to a drillstring component.For example three, four, or more elements of a set of sensor devices ora set of sensor modules 175 may spaced substantially equally around thecircumference of a drillstring component. Sets of sensor module 175 orsensor devices may be used to: measure multiple force (e.g. directional)components, separate multiple force components, remove one or more forcecomponents from a measurement, or compensate for factors such aspressure or temperature. Certain example sensor modules 175 may includesensor devices that are primarily unidirectional. Sensor modules 175 mayemploy commercially available sensor device sets, such as bridges orrosettes.

In certain implementations, one or more sensor modules 175 may becoupled to drillstring components that are used for drilling and thatare subsequently left in the borehole 165. These drillstring componentsmay be used in casing-while-drilling (i.e. drilling with casing)operations. The drillstring components may be included in a completedwell.

In general, the sensor modules 175 convert physical property into one ormore signals. The one or more signals from the sensor modules 175 may beanalog or digital. In certain implementations, one or more sensormodules 175 may be oriented to measure one or more of tension orcompression along the drillstring (i.e. with respect to theup-hole/downhole axis). As used herein, “tensile force” means one ormore of tension or compression forces along the drillstring. In theseimplementations, the sensor modules 175 may be coupled with particulardrillstring components and may include strain responsive sensor devices(e.g. strain gauges). The output of the sensor module 175 may vary basedon the modulus of elasticity of the material of drillstring componentcoupled with the force sensor. This modulus of elasticity may be usedwhen determining the force. In certain implementations, other inputs(e.g. tensile areas) may be used to determine tension or compressionforces in one or more drillstring components from the stresses.Similarly, one or more sensor modules 175 may be oriented to measuretorque on the drillstring (i.e. about the up-hole/downhole axis). Forexample, the sensor modules 175 may be coupled to diameter surfaces(e.g. inner or outer diameters) of drillstring components and may employoutputs from sensor devices (e.g., one or more strain gauges) and mayconsider the shear modulus of elasticity of the drillstring componentmaterial. The torques may be determined based on the stresses from thestrains and other inputs (e.g. polar moment of inertia of the crosssectional area).

A portion of drillpipe 140 is schematically illustrated in FIG. 2. Theillustrated portion of drillpipe includes interfaces 210 between thejoints that form drillpipe 140. Interfaces 210 may include threadedmechanical connections which may have different inner and outerdiameters as compared to the balance of the drillpipe. One or more ofthe interfaces 210 may include communication interfaces. Signals fromsensor modules 175 are coupled to communications medium 205, which maybe disposed in the drillpipe 140 or external to the drillpipe 140.Drillpipe, such as drillpipe 140, with communications medium 205, maycollectively be referred to as a wired drillpipe.

In one example system, the communications medium 205 may be locatedwithin an inner annulus of the drillpipe 140. The communications medium205 may comprise one or more concentric layers of a conductor and aninsulator disposed within the drillstring. In another example system,the drillpipe 140 may have a gun-drilled channel though at leastportions of its length. In such a drillpipe 140, the communicationsmedium 205 may be placed in the gun-drilled channel. In another examplesystem, the communications medium 205 may be fully or partly locatedwithin a protective housing, such as a capillary tubing that runs atleast a portion of the length of the drillpipe 140. The protectivehousing may be attached or biased to the drillpipe inner diameter orstabilized within the drillpipe bore.

The communications medium 205 may be a wire, a cable, a fluid, a fiber,or any other medium. In certain implementations, the communicationsmedium may permit high data transfer rates. The communications medium205 may include one or more communications paths. For example, onecommunications path may connect to one or more sensor modules 175, whileanother communications path may connect another one or more sensorsensors 175. The communications medium 205 may extend from the drillpipe140 to the subs 155, drill collar 145, MWD/LWD tools 150, and the bit160. The communications medium 205 may include physical connectors ormating conductors to complete a transition in the communications medium205 across drillpipe joints and other connections.

The communications medium 205 may transition from one type to anotheralong the drillstring. For example, one or more portions of thecommunications medium 205 may include an LWD system communications bus.One more or portions of the communications medium 205 may comprise a“short-hop” electromagnetic link or an acoustical telemetry link. The“short-hop” electromagnetic links or acoustical telemetry link may beused to interface between drillpipe joints or across difficult-to-wiredrillstring components such as mud motors. In certain implementations,the communications medium may include long-hop (i.e., from a downholetransmitter to a surface receiver) telemetry. For example, the long-hoptelemetry may be mud-pulse telemetry, electromagnetic telemetry throughthe Earth, or acoustic telemetry through the drillstring. The long-hoptelemetry may employ one or more repeaters.

A processor 180 may be used to collect and analyze data from one or moresensor modules 175. This processor 180 may process the force data andprovide an output that is a function of the processed or unprocessedforce data. This output may then be used in the drilling process. Theprocessor may include one or more processing units that operate together(e.g., symmetrically or in parallel) or one or more processing unitsthat operate separately. The processing units may be in the samelocation or in distributed locations. The processor 180 mayalternatively be located below the surface, for example, within thedrillstring. The processor 180 may operate at a speed that is sufficientto be useful in the drilling process. The processor 180 may include orinterface with a terminal 185. The terminal 185 may allow an operator tointeract with the processor 180.

The communications medium 205 may transition to connect the drillstringto the processor 180. The transition may include a mechanical contactwhich may include a rotary brush electrical connection. The transitionmay include a non-contact link which may include an inductive couple ora short-hop electromagnetic link.

The sensor modules 175 may communicate with the processor 180 throughthe communications medium 205. Communications over the communicationsmedium 205 can be in the form of network communications, using, forexample, Ethernet. Each of the sensor modules 175 may be addressableindividually or in one or more groups. Alternatively, communications canbe point-to-point. Whatever form it takes, the communications medium 205may provide high-speed data communication between the sensors in theborehole 165 and the processor 180. The speed and bandwidthcharacteristics of the communications medium 205 may allow the processor180 to perform collection and analysis of data from the sensor modules175 fast enough for use in the drilling process. This data collectionand analysis may be referred to as “real-time” processing. Therefore, asused herein, the term “real-time” means a speed that is useful in thedrilling process.

A portion of a drillstring component is illustrated in FIG. 3. By way ofexample, the illustrated drillstring component is a joint of drillpipe140. Similar implementation may be applied to one or more of subs 155,collars, MWD/LWD tools 175, or the bit 160. The example drillpipe jointhas an elongated box-end upset section. A sensor-module receptacle 305is defined by a recess in the exterior of the drillpipe joint'selongated upset section, below the rotary shoulder connection threads.The sensor-module receptacle 305 may be any suitable size or shape toengage and retain at least a portion of a sensor module 175. The sensormodule 175 may include an electronics module 310. The sensor-modulereceptacle 305 may also include threading to retain at least a portionof the sensor module 175 (e.g. the electronics module 310) withinsensor-module receptacle 305. The drillpipe 140 may also include one ormore drillpipe coupler to couple the sensor modules 175 to the couplers,such as drillpipe coupler 315, to couple signals between portions of thedrillstring and between the sensor module and the communications medium210. Communications medium 205 may be disposed in drillpipe 140, anddrillpipe couplers such as drillpipe coupler 315 may couple signals tothe communications medium 205 and may connect the communications medium205 in the drillpipe 140 with the communications medium in otherdrillstring elements. When the sensor-module receptacle 305 is empty, asensor-module-receptacle cover (not shown) may be used to cover thesensor-module receptacle 305. An example sensor-module-receptacle covermay have an exterior for engaging the sensor-module receptacle 305. FIG.3 shows an example electronics module 310 aligned for insertion into asensor-module receptacle 305.

FIG. 3 shows an example sensor-module-receptacle with electronics module310 removed to highlight remaining details within thesensor-module-receptacle. Example locations within thesensor-module-receptacle are shown on the right side of FIG. 3 forcoupling of one or more sensor devices 340 which may be elements of asensor module 175. The sensor devices may be, for example, strain gaugedevices or sets of strain gauges (e.g. bridges or rosettes). Suchexample locations may be at locations along a wall of sensor-modulereceptacle 305, which may be a substantially cylindrical wall. Examplelocations for mounting sensor devices, may be on the bottom (i.e.radially most inward) surface of sensor-module receptacle 305. Otherexample sensor devices 340 may be ported to the exterior of theelectronics module 310 to measure, for example, external pressure. Othersensor devices 340 may be affixed to any location where the desiredproperty is observed. For example, acceleration sensors or rotationalvelocity sensors may be affixed to a location on or in the drillstringwhere the physical property is incident. One or more sensor devices maybe configured within a sensor-module receptacle 305 with any of thesensor device quantities, symmetry, types, directions, orientations,coupling approaches, and other characteristics of the sensor devicesdiscussed above. Wiring between the sensor devices 340 and theelectronics modules 310 may be routed through holes or grooves from oneor more sensor devices to electronics module 310, using connectors orsoldering.

Sensor modules 175 may also be located in the pin ends of drillstringelements, for example drillpipe joints. A cross-sectional diagram of thepin end 405 of a drillpipe joint is shown in FIG. 4. The pin end 405 ofthe joint may include a sensor module receptacle 305. One or more sensordevices may be configured within sensor-module receptacle 305, forexample, with any of the sensor device quantities, symmetry, types,directions, orientations, coupling approaches, wiring, and othercharacteristics of the sensor devices discussed above. One or moresensor modules 175 may be affixed to the exterior of the drillpipejoint. One or more sensor module 175 may include one or more sensordevices affixed to the exterior of the drillpipe joint, an electronicsmodule located elsewhere (e.g. in a sensor module receptacle 310), andwiring between the two. One or more sensor modules 175 or portions ofsensor module 175 (e.g. sensor devices) may be encased in a covering410. In certain implementations, the covering 410 may include, forexample, a hermetic elastomer or epoxy. One or more of the sensormodules 175 mounted to the exterior of the drillpipe may be located nearthe pin end upset. One or more sensor modules 175 mounted to theexterior of the drillpipe may be located on a smaller cross-sectionalarea section as shown in FIG. 4. Such mounting may provide greaterstrain for a given force or torque as compared to mounting on an upsetsection and may enhance force or torque measurement quality (e.g.resolution). In general, one or more sensor modules 175 may beconfigured to measure one or more of tension, compression, torque, orbending. The pin end 405 insert may include one or more communicationscouplers, such as drillpipe coupler 315. The communications medium 205may be disposed in the drillpipe.

A cross-sectional diagram of an example sub 155 is shown in FIG. 5. Thesub 155 shown in FIG. 5 may include threading to attach between twodrillpipe joints. An elongated box joint 500 of the sub 155 is shown, asan example, with similar implementations possible for other drillstringcomponents. A sensor module 175 is shown comprised of an electronicsmodule 310, one or more sensor devices 340, and wiring 505 between thesensor devices 340 and the electronics module 310. One or more portionsof the exterior of sub 155 may be cut or milled away to form relativelyshallow “flats,” such as flat 510, at one or more locations. One or moreflats 510 may be oriented around the circumference of sub 155. One ormore sensor devices 340 may be adhered to the flats 510. The adheredsensor devices 340 may be protected from the ambient mud with anoverlay. The overlay may be, for example, an epoxy, or an elastomer.Hard facing 515 such as a satellite overlay may also be employed nearthe flats for protection from the borehole wall.

The sensor module 175 may include “dummy” sensor devices proximatelylocated and coupled in a manner to not respond to strain in thedrillstring element. Alternatively, or in addition, one or more sensordevices 340 may be coupled to the inner bore of sub 155. The box-end ofthe sub 155 may be bored back to retain a box-end insert 520. Thebox-end insert 520 may include one or more electronics modules 310.Wiring 505 may be routed from one or more of the sensor devices 340coupled to the exterior of sub 155 through drilled holes and throughhermetic sealing connectors, for connecting or soldering to theelectronics module 310. Wiring 505 may be routed from one or more sensordevices 340 coupled to the inner bore of sub 155 to the electronicsmodule. The electronics module 310 may include a sensor-module couplerto couple the sensor module 175 to the communications medium 205. In oneimplementation, the sub 155 and box-end insert 520 may include one ormore sensor devices 340 configured to measure forces, such as one ormore of axial tension, axial compression, torque, or bending. The sub155 and the box-end insert 520 may further include one or more sensordevices 340 configured to measure acceleration, vibration, rotation, orother properties. The communications medium 205 may be disposed in thesub 155 and the sensor module 175 (e.g., the electronics module 310) mayinclude a sensor-module coupler to couple the sensor devices 340 to thecommunications medium 205. As discussed above, the sub 155 may includecommunication equipment.

A cross-sectional diagram of the box end 605 of a drillpipe joint isshown in FIG. 6. The joint of drillpipe includes a box end 605 adaptedto retain a box-end insert 610. The box end 605 may include an elongatedupset portion. The interior of the box end 605 of the joint may be boredback (beyond the threads) to allow the box-end insert 610 to be placedin the bored-back area. The box-end insert 610 may include one or moresensor modules 175. The sensor modules 175 may be coupled to measure oneor more properties.

In the case of sensor modules 175 to measure one or more pressures, thephysical properties may include, for example, bore pressure or annularpressure exterior to the drillpipe joint. One or more sensor modules 175mounted in the box-end insert 610 may be coupled with a conduit 615 tothe exterior of the drillpipe joint. The conduit 615 may include one ormore drilled holes, one or more capillary tubes, one or more seals, orother means to port the annular pressure to a pressure sensor disposedwithin the drillpipe joint. In general, one or more sensor modules 175may be ported to measure bore or internal pressure.

In the case of sensor modules 175 to measure one or more accelerations,vibrations, or rotational velocities the physical properties may includeacceleration, vibration, or rotational velocity on the interior or theexterior of the drillpipe joint. In general one or more sensor modules175 may be affixed to measure accelerations, vibrations, or rotation.Other sensor modules 175 may be included in the box-end insert 610 tomeasure other properties. One or more sensor modules 175 in the box-endinsert 610 may include two or more sensor devices 340 to measure two ormore properties.

The box-end insert 610 may include one or more communication couplers,such as drillpipe coupler 315. The box-end insert 610 may include othercommunication or processing equipment.

A cross-sectional diagram of an example sub 155 is shown in FIG. 7. Thesub 155 shown in FIG. 7 may include threading to attach between twodrillpipe joints. One or more portions of the sub 155 may be cut away toform sensor-module receptacles 310 to contain a sensor modules 175. Thesub 155 may include a drillpipe coupler 315 to couple the sensor module175 to the communications medium 205. The box-end of the sub 155 may bebored back to retain a box-end insert 610. In the case of sensor modules175 to measure one or more pressure, the box-end insert 610 may includeone or more sensor modules 175 ported to measure annular pressure. Thebox-end insert 610 may include one or more sensor modules 175 ported tomeasure bore pressure. The box-end insert 610 may include one or moresensor modules 175 affixed to measure one or more of acceleration,vibration, or rotation. The box-end insert may include one or morecommunications couplers, such as drillpipe coupler 315. Thecommunications medium may be disposed in the sub 155. As discussedabove, the sub 155 may include communication equipment.

In addition to sensor-module receptacles 310, sensor modules 175 mayalso be mounted on gaskets between joints of drillpipe. Two joints ofdrillpipe 805 and 810 with a gasket 815 are schematically illustrated inFIG. 8. Each of the joints of drillpipe 805 and 810 have a pin end 820and a box end 825. Both the pin and box ends may include threading andload shoulders to allow forming the drillpipe 140 from the joints. Agasket 815 may be placed between the load shoulder of box end 820 ofdrillpipe joint 805 and the load shoulder of pin end 815 of drillpipejoint 810. When the two joints 805 and 810 are joined together, thegasket is located at the interface between the joints. A sensor module175 may be incorporated within gasket 815 or may be mounted to theexterior of gasket 815. The output of the sensor in the sensor module175 may be coupled to the communications medium 205 using one or more ofthe methods described below with respect to FIGS. 11-12. Thisarrangement allows the mounting of sensor modules 175 on the drillstringwithout sensor receptacles in the drillpipe 140. The gasket-mountedsensor modules 175 may be used alone, or in conjunction with sensormodules 175 mounted as described above. In another embodiment, asensor-module receptacle 310 may be created in the exterior of thegasket 815.

An example sensor module 175, shown schematically in FIG. 9, includes asensor device 340 to produce a signal indicative of a physical property.The output from the sensor device 340 may be digital or analog.Depending on the mode of communications used over the communicationsmedium 205, the output from the sensor device 340 may require conversionfrom analog to digital with an analog-to-digital converter 910. Incertain implementations, the sensor module 175 may include a pluralityof analog-to-digital converters 910 to accommodate multiple sensordevices 340. In other implementations, the sensor module 175 may includea multiplexer (not shown) to accommodate multiple sensor devices 340with fewer analog-to-digital converters 910. After the sensor device 340has produced a signal indicative of the measured property, the signalmay be coupled to the communication medium 205 using a communicationscoupler, which may include a electronics module coupler 915 within thesensor module 175 and may include a drillpipe coupler. The electronicsmodule coupler 915 may include a connector 330 for inducing a signal inthe drillpipe coupler 315, shown in FIG. 10. The drillpipe coupler mayinclude a connector 335 for engaging the sensor-module coupler connector330. Connectors may include direct electrical connection and examplesuitable connectors of this type include those from Kemlon and GreeneTweed, both of Houston, Tex.

The communication coupler, which is the combination of the sensor modulecoupler 915 and the drillpipe coupler 315, performs signaltransformations necessary to couple the sensor signal to thecommunications medium 205. One example communication coupler mayre-encode the signal from the sensor device 340 or the analog-to-digitalconverter, include header information, and transmit the signal over thecommunication medium 205.

An example complementary pair of electronics module coupler anddrillpipe coupler connectors 330 and 335 is shown schematically insection view in FIG. 11. The drillpipe-coupler connector 330 includestwo conductive plugs 1105 and 1110, which will protrude from thedrillpipe 140 at the base of the sensor-module receptacle 305. Thecomplementary sensor-coupler connector 335 includes two conductive rings1115 and 1120. This arrangement allows the connectors 330 and 335 tomate when, for example, the electronics module sensor 310 is screwedinto the sensor-module receptacle 305. In such a configuration, thedrillpipe coupler 1005 and the electronics module coupler 915 have adirect electrical connection and the drillpipe coupler may be in directelectrical contact with the communications medium 205.

Another example complementary pair of sensor-coupler anddrillpipe-coupler connectors 330 and 335 is shown in FIG. 12. Theelectronics module connector 330 includes an antenna 1205 and thedrillpipe-coupler connector includes an antenna 1210. In such aconfiguration, the electronics module coupler 615 transmits the signalindicative of the one or more measured properties to the drillpipecoupler using wireless signaling. For example, the sensor and drillpipecoupler may communicate using short-hop telemetry or another wirelesscommunication method. Each of the antennas 1205 and 1210 may be anyantenna or other transducer capable of providing communication betweenthe electronics module coupler 915 and the drillpipe coupler 1005.

In another example system, the electronics module coupler connector 330and the drillpipe-coupler connector 335 may include inductors or coils.The electronics module coupler 915 may pass current though its inductorto create an electromagnetic field indicative of the force sensorsignal. The electromagnetic field, in turn, induces a current in thedrillpipe coupler's inductor. In another example system, the connectors330 and 335 may form two plates of a capacitor allowing a signal to becapacitively induced on the opposing plate. The sensor module 175 or thebase of the sensor-module receptacle 305 may include a coating or insertto provide a dielectric between the connectors 330 and 335 forcapacitive coupling.

An example borehole modeling method that may utilize the systemsdiscussed above is shown in FIG. 13. Borehole models, in general, may bedefined as a representation of the physical nature relating to one ormore of the borehole and the drillstring in the borehole. A boreholemodel may comprise a collection of data on one or more propertiesrelating to the borehole or drillstring, e.g. fluid pressures,drillstring forces, drillstring vibrations, temperatures, etc. Aborehole model may comprise one or both of such data versus boreholelocation, and versus time. A borehole model may cover the entireborehole length, or a portion thereof. A borehole model may cover theentire drillstring length, or a portion thereof. It may include theportion of borehole and drillstring proximate to the MWD/LWD tools,which may be proximate to the hole bottom. A borehole model may includea portion of borehole 165 (or drillstring location) a significantdistance from the bottom-hole, which may be at or proximate to drillpipe140. A borehole model may include two or more sections of borehole ordrillstring. Such sections may correspond, for example, to: (a) rangesof hole angle (e.g. vertical, curve, tangent section, horizontalsection); (b) lengths of common drillstring element type (e.g. overcollars, over heavyweight pipe, over drillpipe); (c) lengths ofdifferent casing diameters or hole diameters; (d) lengths of boreholeexposure to one or more particular formation types; or (e) cased versusopen hole sections.

A borehole model may include an analytical description of one or moreproperties of the borehole or drillstring. A borehole model may includean analytical description of one or more properties of the borehole ordrillstring in combination with measured data, which may be used tocalibrate, tune, or modify the analytical description. A borehole modelmay be represented graphically (e.g. via graphs, plots, logs). Aborehole model may be represented visually via a schematicrepresentation of one or both of a borehole or drillstring, with forexample colors or other symbolic means of displaying one or moreproperties or property variations. A borehole model may be representedtextually, e.g. with a table of numbers.

In general, the borehole modeling system and method may be used toobserve one or more dynamic phenomenon which may occur during thedrilling process. Observation of dynamic phenomena may useful forestablishing drilling process baselines associated with one or moreproperties, which may represent predictions or expectations. Suchobservations may be useful for detecting changes with respect to suchbaselines. Such changes may be results of deliberate changes to theborehole or drillstring (e.g. adding new joint of pipe, changing rotaryRPM, changing mud weight), or may be a result of a condition developingin regard to one or both of the borehole or the drillstring. Theconditions in one or both of the borehole or the drillstring may beimportant to flag, monitor, and/or take action upon. Such conditions mayinclude, for example, and without limitation: cuttings build-up,borehole obstruction, influx, and differential sticking.

Example dynamic phenomenon that may be represented in a borehole modelmay include transients in one or more physical property values thattravel along (e.g., up, down, or both) the physical media (e.g., thedrillstring, the borehole 165, or the drilling fluid). The transientsobserved by the system may include pressure perturbation in the bore orannulus. In some implementations, the pressure perturbations may bedeliberately created (e.g., by venting or pulsing the drilling fluid).In other implementations, the pressure perturbations may be created bydrilling operations, for example, by a mud motor, triplex mud pumps atsurface, the drilling bit 160 on the bottom of the borehole 165, orother elements of the drilling apparatus 100. The transients observed bythe system may include stress or strain waves traveling up or down thedrillstring. The stress or strain waves may be torsional, axial, orboth. The transients observed by the system may include thermaltransients that travel up and down the flow path. For example, thethermal transients may travel with the drilling fluid flow.

The example method includes inducing one or more perturbations in theborehole 165 (block 1305). One or more changes in physical propertiesdue to the perturbation are measured at two or more locations downhole(block 1310). At least one of the two or more locations downhole may beproximate to the drillpipe. The processor 180 may generate a propertyversus depth profile (block 1315). In certain implementationsmeasurements are made at three or more locations downhole, and at leasttwo or more property versus depth profiles are generated. The processor180 may generate a property versus depth versus time profile (block1320). The processor 180 may model the borehole 165 based, at least inpart, on the property versus depth versus time profile (block 1325).

In one example implementation of generating perturbations (block 1305),one or more short pressure transients (e.g., 1 second) may bedeliberately created at surface or downhole to propagate the length ofthe annular returns flow path. The positive or negative perturbation, or“pulse”, would travel the annulus length at the sound speed of themedium (i.e. 4000-5000 ft/sec), similar in manner to that of mud pulsetelemetry, which may be used up the center of the drill pipe 165.

In an example implementation of generating a property versus depthprofile (block 1315), one or more sensor modules 175 may send propertymeasurements to the processor 180. In certain implementations, thesensor modules 175 may time stamp their measurements, while in otherimplementations, the processor 180 may time stamp the measurements. Theprocessor 180 may compare the pulse signature from different sensormodules 175 along the drill string to qualitatively assess one or moremud properties. The processor 180 may performing post-processing on thereceived measurements to deconvolve the multiple reflections (e.g, fromflow area changes).

In some implementations, the property measurements from the sensormodules 175 may be measured substantially simultaneously. As usedherein, “substantially simultaneously” means only that the measurementsare taken in the same time period during which conditions are notexpected to change significantly, in the context of the particularoperational process. Many downhole conditions (e.g., cuttings build-up)may be detected using property versus depth profiles, the values ofwhich are obtained in a time window of minutes. During transientoperational processes such as tripping, and for detection of events orconditions which have a faster time constant, a shorter time window forcollecting and analyzing a property versus depth profile may bepreferred. For example, when measuring property changes due to inducedperturbations which may travel though the drilling fluid at 4,000 to5,000 feet per second, the time interval between property measurementsin a property versus depth profile may be very short to achieve a usefulresolution. Individual measured properties along the drillstring in theproperty versus depth profile may be measured in a short time window(e.g. within a second or less), and such short-time-window measurementprocess may then be repeated one or more additional times during alarger time window of seconds to minutes. An averaged property versusdepth profile may be created from averaging the multiple values for eachproperty sensor. Other statistics may be developed for each measuredproperty in the property versus depth profile. The statistics mayinclude, for example, minimum and maximum values and standard deviation.Averaged values, optionally in conjunction with further statistics, maybe preferred for use during certain operational processes in whichconditions are anticipated to have a dynamic element (e.g. stick-slipduring drilling). In other implementations, the property measurementsfrom the sensor modules 175 may be measures according to a configurablesequence that may be controlled by the processor 180.

In some implementations, the property versus depth profile (block 1315)may include one or more frequency domain values for one or moreproperties at one or more depths. As shown in FIG. 14, the processor 180may determine one or more frequency domain components of a measuredproperty over a time window (block 1405). These frequency domain valuesmay be obtained, for example, by time to frequency domain transformssuch as rolling FFT. To obtain the time domain value for these frequencydomain properties, the processor 180 may receive or compile sufficientmeasurement over a time window. The processor 180 may generate afrequency domain property versus depth profile (block 1410).

The processor 180 may also generate one or more property versus depthversus time profiles (block 1320). In general, the property versus depthversus time profiles may be generated by compiling two or more propertyversus depth profiles obtained at different times. In otherimplementations, the processor 180 may interpolate over time todetermine one or more entries in the property versus depth versus timeprofiles. The processor 180 may generate one or more property versusdepth versus time profiles where the property values are frequencydomain, as described above with respect to block 1315.

In certain implementations, the system may not induce perturbations inthe borehole 165 (block 1305), instead the system may engage in passivelistening for natural perturbations. In one example implementation theprocessor 180 may analyze one or more perturbations that are functionsof the drilling process. For example, the normal drilling relatedpressure “noise” may be picked up by pressure sensors in sensor modules175. Based on the pressure signals, the processor 180 may performanalysis at surface, such as a rolling FFT, to determine frequencycontent and associated power corresponding to periodic bit induced noise(i.e. noise created with every rotation), mud motor noise, noise fromthe triplex mud pumps, and noise from other sources. The relativeattenuation of particular FFT components over time, and between pressuresensors in sensor modules 175 along the drillstring, may be indicativeof changes in the telemetry channel as in the case of deliberateperturbations. This analysis may be qualitative, but certain conditions(e.g., gas influx) and other important flags may be detected in thismanner.

An example system of creating the borehole model (block 1325) is shownin FIG. 15. In general, creating the borehole model may includedetecting, identifying, locating, or characterizing one or moreproperties of the borehole for one or more time intervals. The processor180 may detect a downhole condition (block 1505). In general, a downholecondition may include any regular or irregular, static or dynamic,condition or event along one or both the borehole or drillstring.Example downhole conditions may include, but are not limited to, one ormore of the following: a flow restriction, a cuttings build-up, awash-out, or an influx. The processor may further identify the downholecondition (block 1510). Identifying the downhole condition may includedetermine a likely cause of the down hole condition (e.g., influx,cutting-build up). The processor 180 may locate the downhole condition(block 1515). In some example implementations, the processor 180 mayidentify a range of likely depths for the downhole conditions. Theprocessor may characterize the downhole condition (block 1520). Thecharacterization may include determining a severity or some property ofthe downhole condition. In some example implementations, one or more ofblocks 1505-1520 may be omitted. For example, the processor may be ableto locate a downhole condition that may not be able to identify.

Another example method of modeling the borehole 165 (block 1325) isshown in FIG. 16. The processor 180 may determine one or more changes infrequency domain components of a property over two or more time windows(block 1605). In some example implementations of modeling the borehole165, the processor 180 may observe dynamic phenomenon which occur in thedrilling process that may be represented as standing waves in thephysical media (e.g., the drillpipe 140 or the drilling fluid). Thesephenomenon may result from a substantially periodic forcing function(e.g., mud pumps, drill bit 160 on the bottom of the borehole 140, orrotation of the drillpipe 140) and may be dynamically represented in themedia as standing waves. The phenomenon may be represented as propertymeasurements at a depth with a relatively constant power spectraldistribution (PSD). The relative constancy may represent nothing out ofthe ordinary happening. A change in the frequency content from a firsttime window to a second time window may represent one or more of achange in the forcing function or a change in the medium. If itrepresents a change in the medium, it may be a change that is expected(e.g., the addition of a joint of drillpipe 140), or it may represent anunexpected change, such as the change of a boundary condition such ascontact points between the drillstring and the borehole.

In one example implementation, the processor 180 may analyze a series ofpressure perturbations in the annulus along the drillstring. Theprocessor 180 may track the transient (e.g., the pressure pulse). Theprocessor my observe the overall attenuation of the transient and mayalso observe any change in the frequency content of the transient as ittravels along the annulus. The processor 180 may infer properties of thedrilling fluid such as density change, cuttings load, transition of theprimary phase (e.g. oil vs. water, liquid vs. gas), or the presence ofgas (e.g. a kick).

FIG. 17 shows another example method of modeling the borehole 165 (block1325). The processor 180 may determine an expected set of propertyvalues (block 1705) and compare the expected set of property values withmeasured property values (block 1710). For example, the processor 180may compare the transients characteristics with a set of one or moreexpected values. The expected set of values may be obtained from one ormore of modeling or previously obtained data. Assuming the processor 180collects property values from multiple locations along the drillstring,the location or a range of possible locations of the change in the mediamay be determined. The location of the change in media may be determinedby observing the deviation of a physical property versus depth, usingmeasurement data associated with a single time window. The resolution ofthe locating may depend upon the number of measurement locations. Thisdeviation may be in respect to the set of expected values. Alternativelyor in combination, the location of the change in media may be determinedby establishing a baseline of measurements associated with theperturbation in one or more time windows, and then comparing themeasurements taken at a subsequent time window associated with anothersimilar perturbation. The deviations versus time at each measurelocation may be indicative of the likely location of the downholecondition.

In other example implementations, the processor 180 may analyze a seriesof stress or strain or acceleration perturbations along the drillstring.An impact source (e.g. bit bouncing on bottom), or a torsion source(e.g. bit slip-stick), neither of which may be desirable while drillingnonetheless may occur, and may be employed in an analysis. Alternativelyor in combination, a deliberate stress or strain or accelerationperturbation of the drillstring may be utilized at surface, near bottom,or along the drillstring. The processor 180 may track the transient(e.g., the bit-bounce impact wave). The processor my observe the overallattenuation of the transient and may also observe any change in thefrequency content of the transient as it travels along the drillstring.The processor 180 may infer properties of the drillstring such ascontact with the formation. The processor 180 may compare the transientscharacteristics with a set of one or more expected values. The expectedvalues may be obtained from one or more of modeling or previouslyobtained data. Assuming the processor 180 collects property values frommultiple locations along the drillstring, the location or a range ofpossible locations of the change in the media may be determined. Thelocation of the change in media may be determined by observing thedeviation of the measurement versus depth, using measurement dataassociated with a single time window. The resolution of the locating maydepend upon the number of measurement locations. This deviation may bein respect to the set of expected values. Alternatively or incombination, the location of the change in media may be determined byestablishing a baseline of measurements taken associated with theperturbation in one or more time windows, and then comparing themeasurements taken at a subsequent time window associated with anothersimilar perturbation. The deviations versus time at each location may beindicative of the likely location of a downhole condition, for example acuttings build-up, a borehole deviation (e.g. large dogleg orkeyseating), or a differential sticking.

In one or more of identifying a particular downhole condition (block1510), characterizing the downhole condition (block 1520), and locatingthe downhole condition (block 1515), the processor may consider themanner in which certain downhole conditions affect the properties beingmeasured. Many such relationships are known or knowable. With regard topressure perturbations, acoustic transmission characteristics of fluidsare known to vary with the viscosity, density, bulk modulus, multi-phasecharacteristics, and other properties of such fluids. Such relationshipsmay be determined empirically. With regard to stress or strainperturbations in the drillstring, acoustic transmission characteristicsof steel and other drillstring materials and reflections associatedwith, for example, cross sectional area changes are known or modelable,or empirically determinable. Effects of varying boundary conditions(e.g. clean hole vs. cuttings build-up, differential sticking, dog-legsand key seats) on the acoustic transmission in drillstring componentstoo may be modeled or determined empirically.

The present invention is therefore well-adapted to carry out the objectsand attain the ends mentioned, as well as those that are inherenttherein. While the invention has been depicted, described and is definedby references to examples of the invention, such a reference does notimply a limitation on the invention, and no such limitation is to beinferred. The invention is capable of considerable modification,alteration and equivalents in form and function, as will occur to thoseordinarily skilled in the art having the benefit of this disclosure. Thedepicted and described examples are not exhaustive of the invention.Consequently, the invention is intended to be limited only by the spiritand scope of the appended claims, giving full cognizance to equivalentsin all respects.

1. A borehole analysis method, comprising: measuring at two or moredepths along a drillstring at least one property that is subject toperturbation, where at least one of the depths corresponds to thelocation of a drillpipe; and recording a time when each property ismeasure at each depth; and generating a property versus depth versustime profile based on the property measurements.
 2. The boreholeanalysis method of claim 1, where measuring at two or more depths alongthe drillstring at least one property that is subject to perturbation,comprises: measuring at three or more depths along the drillstring atleast one property that is subject to perturbation.
 3. The boreholeanalysis method of claim 1, where measuring at two or more depths alongthe drillstring at least one property that is subject to perturbation,comprises: measuring at two or more depths the at least one propertyalong the drillstring substantially simultaneously.
 4. The boreholeanalysis method of claim 1, further comprising: generating a model ofthe borehole based, at least in part, on the property versus depthversus time profile.
 5. The borehole analysis method of claim 1, furthercomprising: detecting a downhole condition based, at least in part, onthe property versus depth versus time profile.
 6. The borehole analysismethod of claim 1, further comprising: identifying a downhole conditionbased, at least in part, on the property versus depth versus timeprofile.
 7. The borehole analysis method of claim 1, further comprising:locating a downhole condition based, at least in part, on the propertyversus depth versus time profile.
 8. The borehole analysis method ofclaim 1, further comprising: characterizing a downhole condition based,at least in part, on the property versus depth versus time profile. 9.The borehole analysis method of claim 1, where the perturbation is afunction of the drilling process.
 10. The borehole analysis method ofclaim 1, further comprising: generating the perturbation.
 11. A computerprogram, disposed in a tangible medium, for analyzing a borehole,comprising executable instructions that cause a computer to: receivemeasurements corresponding to two or more depths along a drillstring ofat least one property subject to perturbation, where at least one of thedepths corresponds to the location of a drillpipe; and receive a timewhen each property is measured at each depth; and generate a propertyversus depth versus time profile based on the property measurements. 12.The computer program of claim 11, where the executable instruction thatcause the computer to receive measurements corresponding to two or moredepths along a drillstring of at least one property subject toperturbation at, further cause the computer to: receive measurementscorresponding to three or more depths along a drillstring of at leastone property subject to perturbation.
 13. The computer program of claim11, where the measurements were taken substantially simultaneously. 14.The computer program of claim 11, where the executable instructionsfurther cause the computer to: generate a model of the borehole based,at least in part, on the property versus depth versus time profile. 15.The computer program of claim 11, where the executable instructionsfurther cause the computer to: detect a downhole condition based, atleast in part, on the property versus depth versus time profile.
 16. Thecomputer program of claim 11, where the executable instructions furthercause the computer to: identify a downhole condition based, at least inpart, on the property versus depth versus time profile.
 17. The computerprogram of claim 11, where the executable instructions further cause thecomputer to: locate a downhole condition based, at least in part, on theproperty versus depth versus time profile.
 18. The computer program ofclaim 11, where the executable instructions further cause the computerto: characterize a downhole condition based, at least in part, on theproperty versus depth versus time profile.